US10213729B2 - Hydrocarbon gas decarbonation method - Google Patents

Hydrocarbon gas decarbonation method Download PDF

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US10213729B2
US10213729B2 US14/898,306 US201414898306A US10213729B2 US 10213729 B2 US10213729 B2 US 10213729B2 US 201414898306 A US201414898306 A US 201414898306A US 10213729 B2 US10213729 B2 US 10213729B2
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absorbent solution
amino
methyl
gas
propanol
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US20160144314A1 (en
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Sebastien Gonnard
Nicolas LALOUE
Agnes Leroy
Gauthier Perdu
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IFP Energies Nouvelles IFPEN
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    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
    • B01D53/1425—Regeneration of liquid absorbents
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
    • B01D53/1418—Recovery of products
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
    • B01D53/1456—Removing acid components
    • B01D53/1475—Removing carbon dioxide
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
    • B01D53/1493—Selection of liquid materials for use as absorbents
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
    • C10L3/10—Working-up natural gas or synthetic natural gas
    • C10L3/101—Removal of contaminants
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L3/00—Gaseous fuels; Natural gas; Synthetic natural gas obtained by processes not covered by subclass C10G, C10K; Liquefied petroleum gas
    • C10L3/06—Natural gas; Synthetic natural gas obtained by processes not covered by C10G, C10K3/02 or C10K3/04
    • C10L3/10—Working-up natural gas or synthetic natural gas
    • C10L3/101—Removal of contaminants
    • C10L3/102—Removal of contaminants of acid contaminants
    • C10L3/104—Carbon dioxide
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/164—Injecting CO2 or carbonated water
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/34—Arrangements for separating materials produced by the well
    • E21B43/40—Separation associated with re-injection of separated materials
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
    • B01D2252/20—Organic absorbents
    • B01D2252/204—Amines
    • B01D2252/20478—Alkanolamines
    • B01D2252/20489—Alkanolamines with two or more hydroxyl groups
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L2290/00—Fuel preparation or upgrading, processes or apparatus therefore, comprising specific process steps or apparatus units
    • C10L2290/06—Heat exchange, direct or indirect
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L2290/00—Fuel preparation or upgrading, processes or apparatus therefore, comprising specific process steps or apparatus units
    • C10L2290/12—Regeneration of a solvent, catalyst, adsorbent or any other component used to treat or prepare a fuel
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10L—FUELS NOT OTHERWISE PROVIDED FOR; NATURAL GAS; SYNTHETIC NATURAL GAS OBTAINED BY PROCESSES NOT COVERED BY SUBCLASSES C10G, C10K; LIQUEFIED PETROLEUM GAS; ADDING MATERIALS TO FUELS OR FIRES TO REDUCE SMOKE OR UNDESIRABLE DEPOSITS OR TO FACILITATE SOOT REMOVAL; FIRELIGHTERS
    • C10L2290/00—Fuel preparation or upgrading, processes or apparatus therefore, comprising specific process steps or apparatus units
    • C10L2290/54—Specific separation steps for separating fractions, components or impurities during preparation or upgrading of a fuel
    • C10L2290/541—Absorption of impurities during preparation or upgrading of a fuel
    • Y02C10/06—
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02C—CAPTURE, STORAGE, SEQUESTRATION OR DISPOSAL OF GREENHOUSE GASES [GHG]
    • Y02C20/00—Capture or disposal of greenhouse gases
    • Y02C20/40—Capture or disposal of greenhouse gases of CO2

Definitions

  • the present invention relates to the sphere of decarbonating a hydrocarbon gas, a natural gas for example, by washing with a solvent.
  • the invention provides a method for separating, upon regeneration, the major part of the hydrocarbons co-absorbed by the solvent from the major part of the acid gases absorbed by the solvent. The method thus allows the hydrocarbon content at the regenerator top to be controlled.
  • thermally regenerable liquid solvents for extracting the acid compounds contained in a gas, in particular in a natural gas.
  • solvents are aqueous amine solutions and some physical solvents such as sulfolane, methanol, N-formyl morpholine, acetyl morpholine, propylene carbonate.
  • These methods generally involve a stage of extraction of the CO 2 contained in the gas to be treated by contacting this gas with the regenerated solvent in an absorber operating at the pressure of the gas to be treated, followed by a thermal regeneration stage, generally at a pressure slightly above atmospheric pressure, generally between 1 and 5 bar, preferably between 1.5 and 3 bar.
  • This thermal regeneration is generally carried out in a column equipped at the bottom with a reboiler and at the top with a condenser allowing to cool the acid compounds released by the regeneration and to recycle the condensates to the top of the regenerator as reflux.
  • the acid gas-rich solvent obtained at the absorber bottom can contain significant amounts of dissolved hydrocarbons. It is then common practice to carry out a stage of release of these dissolved hydrocarbons vaporized by simple expansion of the acid gas-rich solvent. This expansion is carried out at an intermediate pressure between that of the raw gas to be treated and that of the thermal regeneration stage, typically of the order of 5 to 15 bar. A gas containing the lighter dissolved hydrocarbons, predominant in proportion by volume, which can be used as combustion gas, is thus separated from the CO 2 -rich solvent.
  • This gas is sometimes washed by a stream of regenerated solvent coming from the thermal stage so as to re-absorb the acid compounds released upon expansion.
  • This washing of the gas released by expansion is generally performed in a column placed directly on the separator drum between the gas and the expanded liquid.
  • the solvent thus laden with acid compounds is directly mixed with the expanded solvent and sent to the thermal regeneration stage.
  • VOC Volatile Organic Compound
  • the VOCs are made up of the following hydrocarbon compounds: linear alkanes (methane is sometimes excluded), cyclo-alkanes, aromatics (benzene, toluene, ethyl benzene and xylenes). It is then necessary to provide an acid gas post-treatment stage such as incineration, which may involve costly equipment and high energy consumption (combustion gas consumption).
  • Acid gas is sometimes reinjected into the well in order to facilitate the extraction stage (EOR), notably in the case of decarbonation. It is therefore necessary to compress the water vapour-saturated acid gas. This compression requiring several stages generates water condensates. The hydrocarbons present in the acid gas are then found in these aqueous condensates, which significantly increases the cost of the associated condensate treatment required to remove the polluting hydrocarbons (notably aromatics).
  • the present invention provides a simple and inexpensive method that requires only a small number of additional equipments for separating, upon regeneration, the major part of the hydrocarbons co-absorbed by the solvent from the major part of the acid gases absorbed by the solvent.
  • the method achieves this goal using a LP (Low Pressure) flash system allowing the hydrocarbon content at the regenerator top to be controlled.
  • the method thus allows the hydrocarbon content at the regenerator top to be controlled, which affords the following advantages:
  • the acid gas obtained with the present invention contains water and CO 2 , and much less hydrocarbons. If the acid gas is to be reinjected for enhanced oil recovery purposes (EOR), the treatments usually necessary for purifying the condensates (water here) extracted from the various compression stages are greatly reduced, or even suppressed. Due to its purity, the water can in some cases be directly recycled to the amine unit with a reduced makeup water consumption,
  • the energy consumption of the method is substantially reduced due to the low combustion gas consumption according to the scheme of the present invention.
  • the invention relates to a method of decarbonating a hydrocarbon gas, a natural gas for example, by washing with a solvent, wherein the following stages are carried out:
  • the temperature and the pressure can be so selected that the gaseous fraction comprises at least 70% of the hydrocarbons contained in the CO 2 -laden absorbent solution and less than 30% of the CO 2 contained in the CO 2 -laden absorbent solution.
  • the temperature can range between the temperature of the CO 2 -laden absorbent solution obtained after stage a) and that of the regenerated absorbent solution obtained after stage c), and the pressure can be above atmospheric pressure.
  • the temperature can for example range between 50° C. and 140° C.
  • the pressure can range between 1.5 and 6 bar.
  • At least part of the regenerated absorbent solution obtained in stage c) can be recycled to stage a) as absorbent solution.
  • the CO 2 -laden absorbent solution prior to stage b), is expanded at a pressure P2 ranging between the pressure used in stage b) and a pressure used in stage a), and at a temperature substantially identical to that of the CO 2 -laden absorbent solution obtained after stage a).
  • Pressure P2 can range between 5 and 15 bar.
  • the absorbent solution can comprise an amine or an amine mixture in solution in water.
  • the amine can be selected from among the group comprising primary amines, secondary amines, sterically hindered secondary amines, tertiary amines, and mixtures of tertiary amines and primary or secondary amines.
  • the primary amine can be selected, alone or in admixture, from among monoethanolamine (MEA), aminoethylethanolamine (AEEA), diglycolamine, 2-amino-2-methyl-1-propanol and the non-N-substituted derivatives thereof.
  • MEA monoethanolamine
  • AEEA aminoethylethanolamine
  • diglycolamine 2-amino-2-methyl-1-propanol
  • 2-amino-2-methyl-1-propanol 2-amino-2-methyl-1-propanol
  • the secondary amine can be selected, alone or in admixture, from among diethanolamine (DEA), diisopropanolamine (DIPA), piperazine and its derivatives wherein at least one nitrogen atom is not substituted, morpholine and its non-N-substituted derivatives, piperidine and its non-N-substituted derivatives, N-(2′-hydroxyethyl)-2-amino-2-methyl-1-propanol, N-(2′-hydroxypropyl)-2-amino-2-methyl-1-propanol, N-(2′-hydroxybutyl)-2-amino-2-methyl-1-propanol.
  • DEA diethanolamine
  • DIPA diisopropanolamine
  • the tertiary amine can be selected, alone or in admixture, from among methyldiethanolamine (MDEA), triethanolamine (TEA), ethyldiethanolamine, diethylethanolamine, dimethylethanolamine, 1-methyl-4-(3-dimethylaminopropyl)-piperazine, 1-ethyl-4-(diethylaminoethyl), 1-methyl-4-hydroxy-piperidine, 1-methyl-2-hydroxymethyl-piperidine, 1,2-bis-(2-dimethylaminoethoxy)-ethane, Bis(dimethylamino-3-propyl)ether, Bis(diethylamino-3-propyl)ether, (dimethylamino-2-ethyl)-(dimethylamino-3-propyl)-ether, (diethylamino-2-ethyl)-(dimethylamino-3-propyl)-ether, (di-methylamino-2-ethyl)-
  • the hindered secondary amine can be selected, alone or in admixture, from among N-(2′-hydroxyethyl)-2-amino-2-methyl-1-propanol, N-(2′-hydroxypropyl)-2-amino-2-methyl-1-propanol, N-(2′-hydroxybutyl)-2-amino-2-methyl-1-propanol.
  • the primary or secondary amines can be selected from the group comprising Monoethanolamine, Diethanolamine, N-butylethanolamine, Aminoethylethanolamine, Diglycolamine, Piperazine, 1-Methylpiperazine, 2-Methylpiperazine, N-(2-hydroxyethyl)piperazine, N-(2-aminoethyl)piperazine, Morpholine, 3-(methylamino)propylamine, 1,6-hexanediamine and all its diversely N-alkylated derivatives such as, for example, N,N′-dimethyl-1,6-hexanediamine, N-methyl-1,6-hexanediamine or N,N′,N′-trimethyl-1,6-hexanediamine.
  • the absorbent solution can be selected from the group made up of sulfolane, methanol, N-formyl morpholine, acetyl morpholine, propylene carbonate, dimethyl ether polyethylene glycol or N-methyl pyrrolidone, or an amine mixture with a physical solvent and water.
  • the gas can be a natural gas.
  • the gas can comprise at least 50 ppmv hydrocarbons. It can comprise less than 100 ppmv H 2 S.
  • the invention also relates to a method wherein the CO 2 -rich gaseous effluent obtained at the end of stage c) is injected into an underground medium in an enhanced oil recovery process.
  • FIG. 1 diagrammatically shows an embodiment of the method according to the prior art
  • FIG. 2 diagrammatically shows an embodiment of the method according to the invention.
  • the present invention provides a simple and inexpensive method that requires only a small number of additional equipments for separating the major part of the hydrocarbons co-absorbed by the solvent from the major part of the acid gases absorbed by the solvent, and thus for controlling the hydrocarbon content at the regenerator top.
  • thermally regenerating the hydrocarbon-depleted absorbent solution so as to release a CO 2 -rich gaseous effluent and to obtain a regenerated absorbent solution.
  • Thermal regeneration can be achieved by distillation or by entrainment of the acid compounds by a vapour stream, an operation commonly referred to as stripping.
  • At least part of the regenerated absorbent solution obtained in stage c) is recycled to stage a) as absorbent solution.
  • the absorbent solution is preferably heated by exchange with a fluid of the process through a heat exchanger, but any other heating means allowing a suitable temperature to be obtained can be used.
  • the absorbent solution thus heated undergoes expansion at a predetermined pressure and temperature so as to release a gaseous fraction predominantly comprising hydrocarbons and to obtain a hydrocarbon-depleted absorbent solution.
  • the pressure and temperature conditions are optimized so that the gaseous fraction comprises at least 50% of the hydrocarbons contained in the acid gas-laden absorbent solution and at most 35% of the acid gas contained in the acid gas-laden absorbent solution.
  • the gas to be treated flows in through line 1 at the bottom of an absorber 2 .
  • the gas from which the acid gases absorbed by the solvent injected at the absorber top through line 26 and the fractions of the co-absorbed compounds, notably hydrocarbons, are extracted is recovered at the top of absorber 2 .
  • This absorber generally operates at temperatures close to or slightly higher than the ambient temperature, typically ranging between 20° C. and 100° C., preferably between 30° C. and 90° C., and at pressures typically ranging between 10 and 200 bar, preferably between 20 and 100 bar.
  • the gas flowing in through line 1 can be a natural gas available at a pressure ranging between 10 and 200 bar, and at a temperature ranging between 20° C. and 100° C.
  • This gas comprises CO 2 , and possibly other acid compounds such as H 2 S, COS, mercaptans and hydrocarbons.
  • the acid gas-rich solvent obtained at the bottom of the absorber through line 4 is expanded by an expansion means 5 and fed into a first flash drum 6 .
  • This first expansion stage is optional for implementing the method according to the invention, but it allows to obtain, through line 7 , a gas containing the major part of the light hydrocarbons co-absorbed by the solvent. This gas is possibly washed by a fraction of the regenerated solvent and the gas thus obtained can be used as fuel gas. This washing procedure, which is optional, is however not shown here.
  • Flash drum 6 operates at a pressure P2 below that of absorber 2 and above that of flash drum 30 . This pressure generally depends on the conditions of use of the fuel gas and it is typically of the order of 5 to 15 bar. This drum operates at a temperature that is substantially identical to that of the solvent obtained at the bottom of absorber 2 .
  • FIG. 2 shows a heat exchanger 27 with a hot utility, but any other suitable means of preheating through exchange with available fluids can be used, provided that it allows the temperature of the acid gas-rich solvent to be brought to the level required for partial vaporization of the compounds absorbed by the solvent.
  • the preheated acid gas-rich solvent is fed through line 29 , possibly after expansion by means of an expansion means 28 , into drum 30 where the vaporized gases and the acid gas-rich solvent are separated.
  • This drum 30 is operated under such pressure and temperature conditions that vaporization of a minor fraction of the acid gases absorbed by the solvent, generally below 35%, preferably below 30%, and of a major fraction of the hydrocarbons absorbed by the solvent, above 50%, preferably above 70%, is obtained.
  • the pressure of drum 30 is lower than that of drum 6 and higher than the atmospheric pressure, preferably ranging between 1.5 and 6 bar.
  • the temperature of drum 30 ranges between that of the acid gas-laden solvent obtained at the bottom of absorber 2 and that of the regenerated solvent obtained at the bottom of regenerator 12 . This temperature can range between 50° C. and 140° C.
  • FIG. 2 shows a heat exchanger 9 with the regenerated solvent obtained at the bottom of regeneration column 12 , but any other suitable preheating means can be used.
  • the acid gas-rich solvent thus preheated is fed through line 11 , possibly after expansion through an expansion means 10 , at the top of regenerator 12 .
  • the acid gases absorbed by the solvent notably CO 2
  • stripping with vapour generated by reboiler 21 at the regenerator bottom are vaporized by an effect commonly referred to as stripping with vapour generated by reboiler 21 at the regenerator bottom.
  • regenerator 12 operates at a pressure generally ranging between atmospheric pressure and 10 bar, preferably between 1.05 and 3 bar.
  • the temperature at the bottom of the regenerator generally ranges between 100° C. and 200° C., preferably between 110° C. and 150° C.
  • regenerator 12 At the bottom of regenerator 12 , a stream of hot regenerated solvent is obtained through line 22 and recycled via line 23 , pump 24 and line 26 to the top of absorber 2 after heat exchange with the acid gas-rich solvent in exchanger 9 .
  • the gases released by partial vaporization in drum 30 are sent through line 31 to a dedicated incinerator.
  • the acid gases separated in drum 15 are fed into line 16 and they can be either discharged or sent to a compression train for EOR.
  • the absorbent solution comprises an amine or an amine mixture in solution in water.
  • the amine can be selected from among the group comprising primary amines, secondary amines, sterically hindered secondary amines, tertiary amines, and mixtures of tertiary amines and primary or secondary amines.
  • the primary amines can be selected, alone or in admixture, from among monoethanolamine (MEA), aminoethylethanolamine (AEEA), diglycolamine, 2-amino-2-methyl-1-propanol and the non-N-substituted derivatives thereof.
  • MEA monoethanolamine
  • AEEA aminoethylethanolamine
  • diglycolamine 2-amino-2-methyl-1-propanol
  • 2-amino-2-methyl-1-propanol 2-amino-2-methyl-1-propanol
  • the secondary amines can be selected, alone or in admixture, from among diethanolamine (DEA), diisopropanolamine (DIPA), piperazine and its derivatives wherein at least one nitrogen atom is not substituted, morpholine and its non-N-substituted derivatives, piperidine and its non-N-substituted derivatives, N-(2′-hydroxyethyl)-2-amino-2-methyl-1-propanol, N-(2′-hydroxypropyl)-2-amino-2-methyl-1-propanol, N-(2′-hydroxybutyl)-2-amino-2-methyl-1-propanol.
  • DEA diethanolamine
  • DIPA diisopropanolamine
  • the tertiary amines can be selected, alone or in admixture, from among methyldiethanolamine (MDEA), triethanolamine (TEA), ethyldiethanolamine, diethylethanolamine, dimethylethanolamine, 1-methyl-4-(3-dimethylaminopropyl)-piperazine, 1-ethyl-4-(diethylaminoethyl), 1-methyl-4-hydroxy-piperidine, 1-methyl-2-hydroxymethyl-piperidine, 1,2-bis-(2-dimethylaminoethoxy)-ethane, Bis(dimethylamino-3-propyl)ether, Bis(diethylamino-3-propyl)ether, (dimethylamino-2-ethyl)-(dimethyl-amino-3-propyl)-ether, (diethylamino-2-ethyl)-(dimethylamino-3-propyl)-ether, (di-methylamino-2-ethyl
  • the hindered secondary amines can be selected, alone or in admixture, from among N-(2′-hydroxyethyl)-2-amino-2-methyl-1-propanol, N-(2′-hydroxypropyl)-2-amino-2-methyl-1-propanol, N-(2′-hydroxybutyl)-2-amino-2-methyl-1-propanol.
  • the primary or secondary amines (activators) can be selected from the group comprising Monoethanolamine, Diethanolamine, N-butylethanolamine, Aminoethylethanolamine, Diglycolamine, Piperazine, 1-Methylpiperazine, 2-Methylpiperazine, N-(2-hydroxyethyl)piperazine, N-(2-aminoethyl)piperazine, Morpholine, 3-(methyl-amino)propylamine, 1,6-hexanediamine and all its diversely N-alkylated derivatives such as, for example, N,N′-dimethyl-1,6-hexanediamine, N-methyl-1,6-hexanediamine or N,N′,N′-trimethyl-1,6-hexanediamine.
  • the absorbent solution can be selected from the group made up of sulfolane, methanol, N-formyl morpholine, acetyl morpholine, propylene carbonate, dimethyl ether polyethylene glycol or N-methyl pyrrolidone, or an amine mixture with a physical solvent and water.
  • the examples given hereafter illustrate the operation and the advantages of the method according to the invention.
  • the first example is given by way of comparison and illustrates a method according to the prior art.
  • the second example illustrates the operation of the method according to the embodiment of the invention.
  • the third example allows to illustrate the performance of the present invention for treating gases with higher aromatic compound contents (BTX).
  • Max HC corresponding to a gas depleted in CO 2 but rich in heavy HC.
  • C 6 + designates all the C 6 to C 12 aliphatic cuts.
  • This gas is fed to the absorber at a temperature of 52° C. and at a pressure of 68.5 bar in order to be contacted with an HEP-activated (80 g/l) aqueous MDEA solution (397 g/l).
  • the solvent is fed to the absorption column at a temperature of 60° C. and at a flow rate of 290 Sm 3 /h for case Max CO 2 and 145 Sm 3 /h for case Max HC.
  • the absorption column is equipped with structured packings. The height of the absorption zone has been optimized so as to meet the specifications relative to the treated gas.
  • the natural gas flows out at a rate of 8 MMSm 3 /d with the composition given in Table 2.
  • the scheme selected is illustrated in FIG. 1 . It does not contain the device for controlling the HO content of the acid gas.
  • VOC contents of the acid gas are as follows:
  • the dimensions of the incinerator are: Combustion chamber diameter: 3500 mm, Combustion chamber height: 12000 mm, Chimney height: 45 meters.
  • the fuel gas consumption dedicated to the acid gas incineration is estimated at 726 kg/h.
  • the invention consists in using a low-pressure column that, after gentle preheating, allows the rich amine to be expanded so as to evaporate the HC (the VOC for example) dissolved in the solvent while controlling the CO 2 loss and the size of the downstream regenerator.
  • the flash gas thus obtained is incinerated in a dedicated incinerator.
  • the LP flash column operates under the following conditions:
  • the additional equipments illustrated in FIG. 2 are as follows:
  • VOC contents of the acid gas are as follows:
  • the water condensed in this stage is notably less polluted by liquid hydrocarbons than in the method according to the prior art. It is then possible to recycle this water without liquid HC purification treatment.
  • the fuel gas consumption dedicated to LP incineration is estimated at 15 kg/h.
  • This example compares the VOC contents of an acid gas obtained after treatment of a BTX-rich raw gas with:
  • the LP flash column operates at 87° C. and 1.5 bar.
  • This gas is fed to the absorber at a temperature of 35.7° C. and at a pressure of 64.1 bar in order to be contacted with an HEP-activated (80 g/l) aqueous MDEA solution (397 g/l).
  • the solvent is fed to the absorption column at a temperature of 44.5° C. and at a flow rate of 78 Sm 3 /h.
  • the absorption column is equipped with a tray section and a structured packing section. The height and the layout of the absorption zone have been optimized so as to meet the specifications relative to the treated gas (50 ppmv CO 2 and 3 ppmv H 2 S).
  • the composition of the treated gas is given in Table 6.
  • the acid gas-laden amine obtained in the absorber bottom at a temperature of 60° C. is then expanded in a MP (Medium Pressure) flash drum at 7.3 bar so as to evaporate part of the light HC to make up fuel gas.
  • the rich amine once expanded, is preheated by the regenerated amine prior to being sent to the regenerator in order to obtain an acid gas-poor solvent and a gas referred to as acid gas at the top, essentially containing CO 2 , H 2 S and a hydrocarbon fraction.
  • the expanded rich amine is preheated, then expanded again (LP flash) at low pressure (1.5 bar here) prior to flowing through the amine/amine exchanger and being regenerated.
  • This additional stage allows to evaporate an additional heavier hydrocarbon fraction containing notably aromatic compounds.
  • the compositions of the acid gases and of the LP flash gas are given in Table 7 hereafter. This table also shows the evolution of the flow rates and of the VOC contents of these gases according to the type of method used. These values allow to determine whether it is necessary to incinerate the acid gas and, if so, the associated fuel gas consumption.
  • This incinerator is however bulkier and costlier in the case of the method according to the prior art because the gas flow to be incinerated is greater (by 59%).
  • the cost of the incinerators has not been estimated but the fuel gas consumption has been assessed to illustrate the gain achieved by implementing the present invention.
  • incineration of the acid gas consumes around 186 kg/h fuel gas against 28 kg/h for incineration of the LP flash gas in the case of the present invention, i.e. a 85% gain.
  • the water recoverable from the acid gas if it is condensed after an acid gas compression stage, contains markedly less hydrocarbons.
  • the gas can be a natural gas, a gas comprising at least 50 ppmv hydrocarbons and/or a gas comprising less than 100 ppmv H 2 S.
  • the hydrocarbon-containing gaseous fraction obtained in stage b) can be sent to a treating unit other than an incinerator, the combustion gas network for example.
  • the invention also relates to an enhanced oil recovery (EOR) method wherein the CO 2 -rich gaseous effluent obtained at the end of stage c) is injected into an underground medium.
  • EOR enhanced oil recovery

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US20160144314A1 (en) 2016-05-26
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